Method and system for distributed control of drilling operations

ABSTRACT

A system including a plurality of subsystems each of which includes a subsystem controller coupled with a sensor configured to obtain a measurement, an actuator, and a subsystem processor. The subsystem processor includes a first memory storing instructions to identify a subsystem state and generate a subsystem performance objective based on the subsystem state. The system also includes a global processor coupled with each of the subsystems, the global processor includes a second memory storing instructions to identify a global system state based on the subsystem state of each subsystem, generate a global performance objective, calculate an updated performance objective for each subsystem, and transmit the updated performance objective to each subsystem. Once received, the subsystem controller in each subsystem activates the actuator to adjust a subsystem parameter to meet the updated performance objective.

FIELD

The present disclosure generally relates to methods and systems fordistributed control among a plurality of systems. In particular, thesubject matter herein relates to a coordination of localized anddistributed control among a plurality of systems in drilling operations.

BACKGROUND

Wellbores can be drilled into the earth for a variety of purposesincluding tapping into hydrocarbon bearing formations to extract thehydrocarbons for use as fuel, lubricants, chemical production, and otherpurposes. Systems for drilling subterranean wellbores can be complex,often involving multiple subsystems. These systems must work inconjunction in order to maintain a functioning well. The drillingsubsystems may include, for instance, a rig subsystem, a drilling fluidsubsystem, and a bottom hole assembly (BHA) subsystem. Each drillingsubsystem typically collects measurements from sensors to detect variousparameters related to the drilling process. Drilling systems aregenerally characterized by subsystem equipment and measurement devicesspread over large distances, which involve communication delays andbandwidth issues.

Several parameters can affect the drilling operations including drillingspeed, mud equivalent circulating density (ECD) and path orientation.Many control methods can control an individual subsystem based on theabove parameters. During the process, several of the systems may pullfrom the same power source. Each system is controlled internally, suchthat the individual systems can update or change their functions basedon different parameters.

BRIEF DESCRIPTION OF THE DRAWINGS

Implementations of the present technology will now be described, by wayof example only, with reference to the attached figures, wherein:

FIG. 1 is a diagram illustrating an exemplary drilling system accordingto the disclosure herein;

FIG. 2 is a diagram illustrating the interactions between drillingsubsystems, according to the disclosure herein;

FIG. 3A illustrates an exemplary system embodiment according to thedisclosure herein;

FIG. 3B illustrates a second exemplary system embodiment according tothe disclosure herein;

FIG. 4 is a block diagram illustrating an exemplary subsystem, accordingto the disclosure herein;

FIG. 5 is a flow chart illustrating a method for distributed controlthroughout a drilling system;

FIG. 6 is a flow chart illustrating a method for obtaining a pluralityof subsystem performance objectives according to the disclosure herein;

FIG. 7 is a flowchart illustrating a method for updating subsystemperformance objectives according to the disclosure herein;

FIG. 8A illustrates a close loop response;

FIG. 8B illustrates a eigenvalue drift;

FIG. 9A illustrates a performance region vs. communication delay graph;

FIG. 9B illustrates an adaptive operation profile vs. communicationdelay; and

FIG. 10 illustrates an adaptive operation profile based on eigenvaluedrift analysis.

DETAILED DESCRIPTION

It will be appreciated that for simplicity and clarity of illustration,where appropriate, reference numerals have been repeated among thedifferent figures to indicate corresponding or analogous elements. Inaddition, numerous specific details are set forth in order to provide athorough understanding of the embodiments described herein. However, itwill be understood by those of ordinary skill in the art that theembodiments described herein can be practiced without these specificdetails. In other instances, methods, procedures and components have notbeen described in detail so as not to obscure the related relevantfeature being described. Also, the description is not to be consideredas limiting the scope of the embodiments described herein. The drawingsare not necessarily to scale and the proportions of certain parts havebeen exaggerated to better illustrate details and features of thepresent disclosure.

Several definitions that apply throughout this disclosure will now bepresented. The term “coupled” is defined as connected, whether directlyor indirectly through intervening components, and is not necessarilylimited to physical connections. The connection can be such that theobjects are permanently connected or releasably connected. The terms“comprising,” “including,” and “having” are used interchangeably in thisdisclosure. The terms “comprising,” “including,” and “having” mean toinclude, but not necessarily be limited to, the things so described.

Disclosed herein are a method and a system for combining localized anddistributed control of a drilling system having a smart communicationdevice. Real time data is obtained from each of a plurality ofsubsystems, each of which is controlled by a subsystem controllerconfigured to maximize a predetermined parameter of each subsystem. Eachsubsystem can transmit data to a global processor configured to maximizea predetermined parameter of the entire drilling system based at leaston the data compiled from each of the subsystems. The global processorcan generate an updated performance objective for each of thesubsystems. The updated performance objective can be independent fromthe local subsystem performance objective. The updated performanceobjective can be configured to prevent detrimental competition for useof the resources by one or more subsystems. The updated performanceobjectives can be transmitted to the subsystem controllers for eachsubsystem, the subsystem controllers can then adjust the subsystemactuator to meet the performance objective.

FIG. 1 illustrates a diagram of an exemplary embodiment of a wellboreoperating environment 10 in which a drilling control apparatus, method,and system may be deployed in accordance with certain embodiments of thepresent disclosure. The wellbore operating environment 10 includes aplurality of drilling subsystems. For example, FIG. 1 depicts thewellbore operating environment 10 as including a bottom hole assembly(BHA) subsystem 25, drilling fluid system 50, and a rig subsystem 75.However, the wellbore operating environment 10 may include any number ofsubsystems. Additionally, each of the subsystems illustrated in FIG. 1may be further divided into additional subsystems, or may themselves beincluded in other subsystems, without departing from the scope andspirit of the present disclosure.

As depicted in FIG. 1, the wellbore operating environment 10 may includea drilling rig 12 positioned above a borehole 14. The drilling rig 12includes a drill string 20 disposed within the borehole 14. A BHAsubsystem 25 is located at the downhole end of the drill string 20. TheBHA subsystem 25 includes a drill bit 22 that penetrates the earthformation 24 to form a borehole 14. The BHA subsystem 25 furtherincludes a fluid-driven motor assembly 70 that drives drill bit 22. TheBHA subsystem 25 may provide directional control of the drill bit 22. Inat least one aspect of the present disclosure, the drill bit 22 is arotatable drill bit and the BHA subsystem is a steerable BHA subsystem25 including a Measurement While Drilling (MWD) system with varioussensors 18 to provide information about the earth formations 24 anddownhole drilling parameters. The MWD sensors in the BHA subsystem 25may include, but are not limited to, a device for measuring theformation resistivity near the drill bit, a gamma ray device formeasuring the formation gamma ray intensity, devices for determining theinclination and azimuth of the drill string, and pressure sensors formeasuring drilling fluid pressure downhole. The MWD may also includeadditional/alternative sensing devices for measuring shock, vibration,torque, telemetry, etc. The BHA subsystem 25 may further includeactuators capable of steering the drill bit 22 or otherwise adjustingthe path direction of the drill bit 22 and drill string 20. In at leastone aspect of the present disclosure, the BHA subsystem 25 includes asubsystem controller capable of processing data obtained from sensors18. The subsystem controller can adjust the path direction of the drillbit 22 and drill string 20 in response to the data by sending a commandsignal to one or more actuators capable of adjusting the parameter. Thesensors 18 may transmit data through a subsystem controller to a globalprocessor 100 on the earth's surface using telemetry such asconventional mud pulse telemetry systems or any wired, fiber optic, orwireless communication system. The global processor 100 can include anysuitable computer, controller, or data processing apparatus capable ofbeing programmed to carry out the method and apparatus as furtherdescribed herein. As such, the global processor 100 can process thesensor data in accordance with the embodiments of the present disclosureas described herein.

In the alternative, the global processor 100 can transmit the data toanother location for processing. For example, the global processor 100can be communicatively coupled with each of the subsystems via thesubsystem controllers and a network 110. The network 110 can be anynetwork for transmitting and receiving data from the subsystems, suchas, a local area network (LAN), wide area network (WAN), and telephonenetwork, such as a Public Switched Telephone Network (PTSN), anintranet, the Internet, or combinations thereof. In at least one aspectof the present disclosure, the network 110 can be a telemetry network,such as a mud pulse telemetry network, an electromagnetic telemetrynetwork, a wired pipe network, fiber optics, a pipe-in-pipe network, anacoustic telemetry network, a torsion telemetry network, or combinationsthereof. In the alternative, the network 110 can be a combination oftraditional or telemetry networks.

The global processor 100 can receive measurement data and subsystemstate information from one or more subsystem controllers. As usedherein, “subsystem state” refers to a time-dependent subsystem state orset of subsystem states that can be directly measured by a sensor orcalculated or estimated, at least in part, from one or more sensormeasurements. The global processor 100 can also transmit instructions toeach of the subsystem controllers. In at least one aspect of the presentdisclosure, the global processor 100 can send instructions to each ofthe subsystem controllers sufficient to coordinate control of thedrilling subsystems during drilling operations.

Additionally, network 110 can facilitate communication with servers orother shared data systems. For example, the global processor 100 canshare subsystem sensor measurement data, subsystem controller actions,and subsystem state information with servers, computers, or devices overnetwork 110.

In at least one aspect of the present disclosure, the BHA subsystem 25can include a Logging While Drilling (LWD) System with additionalsensors or logging tools 16. The logging tools, sensors, or instruments16, can be any conventional logging instrument, such as acoustic(sonic), neutron, gamma ray, density, photoelectron, nuclear magneticresonance, or any other conventional logging instrument, or combinationsthereof, which can be used to measure lithology or porosity of earthformations surrounding the borehole 14. The sensors or logging tools 16can transmit data to the global processor 100 through the subsystemcontrollers using telemetry such as those discussed above. As statedabove, the global processor 100 can process the sensor data or transmitthe data for processing at another location.

The BHA subsystem 25 can also include additional sensors in conjunctionwith the fluid-driven motor 70 that can monitor the revolutions perminute (RPM) of the motor 70 and identify changes in torque or powerrequired to maintain constant rotation, such as a torque meter. Suchsensors may be internal or external to the fluid-driven motor 70.

In addition to MWD sensors, LWD sensors, and instrumentation, wirelineinstrumentation can also be used in conjunction with the BHA subsystem25. The wireline instrumentation can include any conventional logginginstrumentation which can be used to measure the lithology and/orporosity of earth formations surrounding a borehole, for example,acoustic, neutron, gamma ray, density, photoelectric, nuclear magneticresonance, or any other conventional logging instrument, or combinationsthereof.

As depicted in FIG. 1, a mud circulation subsystem, or drilling fluidsubsystem, 50 can pump drilling mud 26 via pumps 38 from a storagereservoir pit 28 near the wellhead 30, down an axial passageway (notillustrated) through the drill string 20, through the fluid-driven motorassembly 70, and out of a plurality of apertures within the drill bit22. As used herein, the term “drilling mud” may be used interchangeablywith “drilling fluid” to refer to both drilling mud alone and a mixtureof drilling mud and formation cuttings, or alternatively, to refer toboth drilling fluid alone and a mixture of drilling fluid and formationcuttings. The drilling mud 26 the flows back to the surface through theannular region 32 between the drill string 20 and the sidewalls 36 ofthe borehole 14. A metal casing 34 may be positioned in the borehole 14above the drill bit 22 configured to maintain the integrity of the upperportion of the borehole 14 and prevent fluid transmission (such asdrilling mud 26) between borehole 14 and earth formation 24.

The drilling fluid subsystem 50 can include one or more sensors capableof measuring the pumping rate or the downhole drilling fluid flow rate.The drilling fluid subsystem 50 can include one or more actuatorsconfigured to adjust parameters with respect to pump 38, including, butnot limited to, pump rate and the drilling fluid flow rate. The drillingmud can travel through a mud supply line 40 which is coupled with acentral passageway extending throughout the length of the drill string20 and exits through apertures in the drill bit 22 to cool and lubricatethe drill bit 22 and carry formation cuttings to the surface. Thecuttings and mud mixture pass through a fluid exhaust conduit 42,coupled with the annular region 32 at the well head 30, into a troughsystem 45 that can include shakers and a centrifuge (not shown). Theshakers can separate a majority of solids, such as cuttings and fines,from the drilling mud 26. The cleaned mud is then returned to the mudstorage pit 28.

The drilling fluid subsystem 50 can include sensors in the trough system45 configured to analyze the nature as well as the volume, quantity, orweight of the cuttings and fines being removed from the well.Additionally, the drilling fluid subsystem 50 may include sensorsconfigured to determine the particle size distribution (PSD), density,and/or visual characteristics of the cuttings. For example, the drillingfluid subsystem 50 may include sensors capable of determining whetherthe cuttings are being efficiently removed from the borehole 14. Thedrilling fluid subsystem 50 can include actuators configured to adjustor control the performance of the shakers and centrifuges. For example,the actuators can control shaker parameters such as screen desk angle,vibration, G-force, and mud equivalent circulating density (ECD).

The drilling fluid subsystem 50 can further include one or more sensorsconfigured to determine fluid properties of the drilling mud. Thedrilling fluid subsystem 50 can also include one or more mixers 35 tomix mud obtained from the mud storage pit with appropriate additives.For example, the mixers 35 can control the rheological properties of thedrilling fluid as well as the density, electrical stability, percentsolids, oil/water ratio, acidity (pH), salinity, and particle sizedistribution. The drilling fluid subsystem 50 can include one or moreactuators to control the properties of the drilling fluid. For example,the actuators can control additive supply valves, feed rates, mixturecomposition, discharge rates, and other aspects of the mixing process.

As described above, the wellbore operating environment 10 can furtherinclude a rig subsystem 75. The rig subsystem 75 can include a top drivemotor 72, a draw works 73, a rotary table 76, and a rotary table motor74. The rotary table motor 74 can rotate the drill string 20 or, in thealternative, the drill string 20 can be rotated via the top drive motor72. The rig subsystem 75, at least in part, drives the drill bit 22 byproviding sufficient weight-on-bit (WOB), revolutions per minute (RPM)and torque to create the borehole 14. The rig subsystem 75 can includeone or more sensors to measure, for instance, RPM, WOB, torque-on-bit(TOB), rate of penetration (ROP), well depth, hook load, and standpipepressure. Additionally, the rig subsystem 75 can include actuators toadjust or control the above described drilling parameters.

Although FIG. 1 generally depicts a vertical wellbore, it would beobvious to those skilled in the art that the present disclosure isequally well suited for use in wellbores having other orientationsincluding horizontal wellbores, slanted wellbores, multilateralwellbores or the like. Additionally, even though FIG. 1 depicts anonshore operation, the present disclosure is equally well-suited for usein offshore operations. Offshore oil rigs that can be used in accordancewith the present disclosure include, but are not limited to, floaters,fixed platforms, gravity-based structures, drillships, semi-submersibleplatforms, jack-up drilling rigs, tension-leg platforms, and the like.The present disclosure is also suited for use in rigs ranging anywherefrom small in size and portable to bulky and permanent.

Although shown and described with respect to a rotary drill system inFIG. 1, many types of drills can be employed in carrying out embodimentsof the invention including, but not limited to, Auger drills, air coredrills, cable tool drills, diamond core drills, percussion rotary airblast (RAB) drills, reverse circulation drills, and the like.Additionally, the present disclosure is suited for use in any drillingoperation that generates a subterranean borehole. For example, thepresent disclosure is suited for drilling for hydrocarbon or mineralexploration, environmental investigations, natural gas extraction,underground instillation, mining operations, water wells, geothermalwells, and the like.

An exemplary interaction between the above described drilling systems isdetailed in FIG. 2. As depicted in FIG. 2, control actions taken by anyof the individual drilling subsystems can affect the performance of oneor more other drilling subsystems. For example, the drilling fluidsubsystem 50 provides drilling mud that is circulated downhole to coolthe drill bit and transport the cuttings to the surface for disposal.The drilling fluid subsystem 50 includes a mud conditioning system toprocess the circulated drilling fluid with shakers, centrifuges, andother cutting removal equipment. Before the drilling fluid isrecirculated, make-up water and other additives can be added to thedrilling fluid to obtain the desired density and rheological profile. Assuch, the drilling fluid subsystem 50 directly determines the drillingfluid flow rate (downhole pumping rate) and the properties of thedrilling fluid (for example, the rate of additive or make-up water addedto the system). The drilling fluid properties and downhole drillingfluid flow rate can affect the performance and control parameters of therig 75 and BHA 25 subsystems. For example, the drilling fluid propertiesand flow rate can determine in part the ability of the BHA subsystem 25to effectively control the well path direction. The drilling fluidproperties and flow rate can also affect the rig subsystem controlparameters, such as WOB, TOB, or RPM, necessary to create the boreholeor achieve the desired ROP.

Similarly, a change in the well path direction, controlled by the BHAsubsystem 25, can require changes in the drilling fluid properties orflow rate, controlled by the drilling fluid subsystem 50. The well pathdirection (controlled by the BHA subsystem 25) can additionally affectthe rig subsystem 75 control decisions. Likewise, the manipulation ofrig subsystem 75 variables, such as WOB and RPM, can affect the controlbehaviors of the BHA subsystem 25 and the drilling fluid subsystem 50.

Referring back to FIG. 1, each subsystem can include a subsystemcontroller that is communicatively coupled with at least one subsystemsensor and at least one subsystem actuator. The subsystem controller canreceive measurement data collected by subsystem sensors and determine alocal subsystem state based in part on the measurements received fromthe subsystem sensors. Additionally, the subsystem controller can sendcommand signals to the subsystem actuators and cause the actuators toadjust one or more drilling parameter. For example, the actuators canconvert the command signals from subsystem controllers into actions suchas movement of a control valve shaft or the change of speed of a pump.The command signals can include, but are not limited to, electrical,pneumatic, hydraulic, acoustic, electromagnetic radiation, and variouscombinations thereof. The actuators can be of various kinds, including,but not limited to, variable speed motors, variable speed drives,pneumatic actuators, electrical actuators, hydraulic actuators, rotaryactuators, servo motor actuators, and various combinations thereof. Insome cases, the subsystem controller can send command signals to a lowerlevel controller configured to activate an actuator to adjust asubsystem parameter. The lower level controllers can be relativelysimple controllers such as a proportional-integral-derivative (PID) typecontroller or a control loop feedback mechanism controller.

The subsystem controller can include any suitable computer, controller,or data processing apparatus capable of being programmed to carry outthe method and apparatus as further described herein. FIGS. 3A and 3Billustrate exemplary subsystem controller embodiments which can beemployed to practice the concepts, methods, and techniques disclosedherein. The more appropriate embodiment will be apparent to those ofordinary skill in the art when practicing the present technology.Persons of ordinary skill in the art will also readily appreciate thatother system embodiments are possible.

FIG. 3A illustrates a conventional system bus computing systemarchitecture 300 wherein the components of the system are in electricalcommunication with each other using a bus 305. System 300 can include aprocessing unit (CPU or processor) 310 and a system bus 305 that couplesvarious system components including the system memory 315, such as readonly memory (ROM) 320 and random access memory (RAM) 335, to theprocessor 310. For example, the global processor of FIG. 1 can be a formof this processor 310. The system 300 can include a cache of high-speedmemory connected directly with, in close proximity to, or integrated aspart of the processor 310. The system 300 can copy data from the memory315 and/or the storage device 330 to the cache 312 for quick access bythe processor 310. In this way, the cache 312 can provide a performanceboost that avoids processor 310 delays while waiting for data. These andother modules can control or be configured to control the processor 310to perform various actions. Other system memory 315 may be available foruse as well. The memory 315 can include multiple different types ofmemory with different performance characteristics. It can be appreciatedthat the disclosure may operate on a computing device 300 with more thanone processor 310 or on a group or cluster of computing devicesnetworked together to provide greater processing capability. Theprocessor 310 can include any general purpose processor and a hardwaremodule or software module, such as a first module 332, a second module334, and third module 336 stored in storage device 330, configured tocontrol the processor 310 as well as a special-purpose processor wheresoftware instructions are incorporated into the actual processor design.The processor 310 may essentially be a completely self-containedcomputing system, containing multiple cores or processors, a bus, memorycontroller, cache, etc. A multi-core processor may be symmetric orasymmetric.

The system bus 305 may be any of several types of bus structuresincluding a memory bus or a memory controller, a peripheral bus, and alocal bus using any of a variety of bus architectures. A basicinput/output (BIOS) stored in ROM 320 or the like, may provide the basicroutine that helps to transfer information between elements within thecomputing device 300, such as during start-up. The computing device 300further includes storage devices 330 or computer-readable storage mediasuch as a hard disk drive, a magnetic disk drive, an optical disk drive,tape drive, solid-state drive, RAM drive, removable storage devices, aredundant array of inexpensive disks (RAID), hybrid storage device, orthe like. The storage device 330 can include software modules 332, 334,336 for controlling the processor 310. The system 300 can include otherhardware or software modules. The storage device 330 is connected to thesystem bus 305 by a drive interface. The drives and the associatedcomputer-readable storage devices provide non-volatile storage ofcomputer-readable instructions, data structures, program modules andother data for the computing device 300. In one aspect, a hardwaremodule that performs a particular function includes the softwarecomponents shorted in a tangible computer-readable storage device inconnection with the necessary hardware components, such as the processor310, bus 305, and so forth, to carry out a particular function. In thealternative, the system can use a processor and computer-readablestorage device to store instructions which, when executed by theprocessor, cause the processor to perform operations, a method or otherspecific actions. The basic components and appropriate variations can bemodified depending on the type of device, such as whether the device 300is a small, handheld computing device, a desktop computer, or a computerserver. When the processor 310 executes instructions to perform“operations”, the processor 310 can perform the operations directlyand/or facilitate, direct, or cooperate with another device or componentto perform the operations.

To enable user interaction with the computing device 300, an inputdevice 345 can represent any number of input mechanisms, such as amicrophone for speech, a touch-sensitive screen for gesture or graphicalinput, keyboard, mouse, motion input, speech and so forth. An outputdevice 342 can also be one or more of a number of output mechanismsknown to those of skill in the art. In some instances, multimodalsystems can enable a user to provide multiple types of input tocommunicate with the computing device 300. The communications interface340 can generally govern and manage the user input and system output.There is no restriction on operating on any particular hardwarearrangement and therefore the basic features here may easily besubstituted for improved hardware or firmware arrangements as they aredeveloped.

Storage device 330 is a non-volatile memory and can be a hard disk orother types of computer readable media which can store data that areaccessible by a computer, such as magnetic cassettes, flash memorycards, solid state memory devices, digital versatile disks (DVDs),cartridges, RAMs 325, ROM 320, a cable containing a bit stream, andhybrids thereof.

The logical operations of the various embodiments are implemented as:(1) a sequence of computer implemented steps, operations, or proceduresrunning on a programmable circuit with a general use computer, (2) asequence of computer implemented steps, operations, or proceduresrunning on a specific-use programmable circuit; and/or (3)interconnected machine modules or program engines within theprogrammable circuits. The system 300 shown in FIG. 3A can practice allor part of the recited methods, can be a part of the recited systems,and/or can operate according to instructions in the recited tangiblecomputer-readable storage devices.

One or more parts of the example computing device 300, up to andincluding the entire computing device 300, can be virtualized. Forexample, a virtual processor can be a software object that executesaccording to a particular instruction set, even when a physicalprocessor of the same type as the virtual processor is unavailable. Avirtualization layer or a virtual “host” can enable virtualizedcomponents of one or more different computing devices or device types bytranslating virtualized operations to actual operations. Ultimatelyhowever, virtualized hardware of every type is implemented or executedby some underlying physical hardware. Thus, a virtualization computelayer can operate on top of a physical compute layer. The virtualizationcompute layer can include one or more of a virtual machine, an overlaynetwork, a hypervisor, virtual switching, and any other virtualizationapplication.

The processor 310 can include all types of processors disclosed herein,including a virtual processor. However, when referring to a virtualprocessor, the processor 310 includes the software components associatedwith executing the virtual processor in a virtualization layer andunderlying hardware necessary to execute the virtualization layer. Thesystem 300 can include a physical or virtual processor 310 that receivesinstructions stored in a computer-readable storage device, which causesthe processor 310 to perform certain operations. When referring to avirtual processor 310, the system also includes the underlying physicalhardware executing the virtual processor 310.

FIG. 3B illustrates an example computer system 350 having a chipsetarchitecture that can be used in executing the described method andgenerating and displaying a graphical user interface (GUI). Computersystem 350 can be computer hardware, software, and firmware that can beused to implement the disclosed technology. System 350 can include aprocessor 355, representative of any number of physically and/orlogically distinct resources capable of executing software, firmware,and hardware configured to perform identified computations. Processor355 can communicate with a chipset 360 that can control input to andoutput from processor 355. Chipset 360 can output information to outputdevice 365, such as a display, and can read and write information tostorage device 370, which can include magnetic media, and solid statemedia. Chipset 360 can also read data from and write data to RAM 375. Abridge 380 for interfacing with a variety of user interface components385 can include a keyboard, a microphone, touch detection and processingcircuitry, a pointing device, such as a mouse, and so on. In general,inputs to system 350 can come from any of a variety of sources, machinegenerated and/or human generated.

Chipset 360 can also interface with one or more communication interfaces390 that can have different physical interfaces. Such communicationinterfaces can include interfaces for wired and wireless local areanetworks, for broadband wireless networks, as well as personal areanetworks. Some applications of the methods for generating, displaying,and using the GUI disclosed herein can include receiving ordereddatasets over the physical interface or be generated by the machineitself by processor 355 analyzing data stored in storage 370 or RAM 375.Further, the machine can receive inputs from a user via user interfacecomponents 385 and execute appropriate functions, such as browsingfunctions by interpreting these inputs using processor 355.

It can be appreciated that systems 300 and 350 can have more than oneprocessor 310, 355 or be part of a group or cluster of computing devicesnetworked together to provide processing capability. For example, theprocessor 310, 355 can include multiple processors, such as a systemhaving multiple, physically separate processors in different sockets, ora system having multiple processor cores on a single physical chip.Similarly, the processor 310 can include multiple distributed processorslocated in multiple separate computing devices, but working togethersuch as via a communications network. Multiple processors or processorcores can share resources such as memory 315 or the cache 312, or canoperate using independent resources. The processor 310 can include oneor more of a state machine, an application specific integrated circuit(ASIC), or a programmable gate array (PGA) including a field PGA.

Methods according to the aforementioned description can be implementedusing computer-executable instructions that are stored or otherwiseavailable from computer readable media. Such instructions can compriseinstructions and data which cause or otherwise configured a generalpurpose computer, special purpose computer, or special purposeprocessing device to perform a certain function or group of functions.portions of computer resources used can be accessible over a network.The computer executable instructions may be binaries, intermediateformat instructions such as assembly language, firmware, or source code.Computer-readable media that may be used to store instructions,information used, and/or information created during methods according tothe aforementioned description include magnetic or optical disks, flashmemory, USB devices provided with non-volatile memory, networked storagedevices, and so on.

For clarity of explanation, in some instances the present technology maybe presented as including individual functional blocks includingfunctional blocks comprising devices, device components, steps orroutines in a method embodied in software, or combinations of hardwareand software. The functions these blocks represent may be providedthrough the use of either shared or dedicated hardware, including, butnot limited to, hardware capable of executing software and hardware,such as a processor 310, that is purpose-built to operate as anequivalent to software executing on a general purpose processor. Forexample, the functions of one or more processors represented in FIG. 3Amay be provided by a single shared processor or multiple processors.(Use of the term “processor” should not be construed to referexclusively to hardware capable of executing software). Illustrativeembodiments may include microprocessor and/or digital signal processor(DSP) hardware, ROM 320 for storing software performing the operationsdescribed below, and RAM 335 for storing results. Very large scaleintegration (VLSI) hardware embodiments, as well as custom VLSIcircuitry in combination with a general purpose DSP circuit, may also beprovided.

The computer-readable storage devices, mediums, and memories can includea cable or wireless signal containing a bit stream and the like.However, when mentioned, non-transitory computer-readable storage mediaexpressly exclude media such as energy, carrier signals, electromagneticwaves, and signals per se.

Devices implementing methods according to these disclosures can comprisehardware, firmware and/or software, and can take any of a variety ofform factors. Such form factors can include laptops, smart phones, smallform factor personal computers, personal digital assistants, rackmountdevices, standalone devices, and so on. Functionality described hereinalso can be embodied in peripherals or add-in cards. Such functionalitycan also be implemented on a circuit board among different chips ordifferent processes executing in a single device.

The instructions, media for conveying such instructions, computingresources for executing them, and other structures for supporting suchcomputing resources are means for providing the functions described inthese disclosures.

A general subsystem 120 according to the disclosure herein isillustrated in FIG. 4. The subsystem 120 can contain a subsystemcontroller 122 coupled with a processor 124, wherein the processorfurther comprises a memory 126. The subsystem controller 122 is furthercommunicatively coupled with a sensor 128 and an actuator 130 via anetwork 110. The network 110 can be any network capable of transmittingand receiving data, as described in detail above with respect to FIG. 1.While FIG. 4 generally depicts a subsystem 120 having a single sensor128 and a single actuator 130, it should be obvious to those skilled inthe art that the subsystem can include any number of sensors oractuators without departing from the disclosure.

A method for distributed control of a drilling system, such as the onedescribed above with respect to FIGS. 1-4, can follow the method 500 asdepicted in FIG. 5. For example, beginning at block 510, a drillingsystem is provided comprising a plurality of subsystems throughout thedrilling system. While the illustrate example shows a drilling systemcomprising three subsystems, it should be noted that any number ofsubsystems can be present. At block 520, a global processor determines aglobal performance objective for the drilling system as a whole. Theglobal performance objective can be based, at least in part, on theoptimization of any number of goals, for example, cost minimization orequipment life extension.

At block 530, a plurality of measurements is obtained from each of theplurality of sensors at different points throughout the drilling system.Each of the measurements can be related to a different subsystem, or adifferent parameter within a subsystem. At block 540, the measurementsobtained are transmitted to a global processor. At block 550, the globalprocessor determines a controller design for subsystem 1. The controllerdesign can be, but is not limited to, a Model Predictive Control (MPC).The controller design can take into account local constraints ofsubsystem 1 as well as the real-time physical inputs for each of thesubsystems, such that the controller design is specific to subsystem 1.At block 560, the controller design is transmitted to the subsystemcontroller of subsystem 1, such that the subsystem controller canactivate the subsystem 1 actuator in order to bring the subsystem intocompliance with the received controller design.

Similarly, at block 552 a controller design for subsystem 2 isdetermined, taking into account the local constraints of subsystem 2. Atblock 562, the subsystem controller of subsystem 2 receives thecontroller design and activates the subsystem 2 actuator in order tobring the subsystem into compliance with the controller design. The sameoccurs with respect to subsystem 3 at blocks 554 and 564, respectively.

An alternative method for distributed control of a drilling system canfollow the flow diagrams as depicted in FIGS. 6 and 7. A method 600 forlocalized control is shown in FIG. 6. For example, beginning at block610, a drilling system is provided comprising a plurality of subsystems,as described above with respect to FIG. 5. While the illustrated exampleshows a drilling system comprising three subsystems, it should be notedthat any number of subsystems can be present. At block 620, a sensor ofsubsystem 1 obtains a measurement and the processor identifies asubsystem state for subsystem 1 based at least in part on the obtainedmeasurement. The measurement taken by the sensor can be, but is notlimited to, hook load, top-drive torque, pump/choke, pressure/opening,BHA tool-face, and rotational position and speed. At block 640, thesubsystem 1 processor generates a performance objective for subsystem 1.

Similarly, at block 622 a measurement is obtained from the sensor ofsubsystem 2 and a subsystem state is identified. At block 642, asubsystem performance objective is generated for subsystem 2. The sameprocess occurs at blocks 624 and 644 with respect to subsystem 3. Atblock 660, the performance objectives of subsystems 1, 2, and 3 aretransmitted to a global processor. The method repeats itself such thatthe subsystem state and subsystem performance objective for eachsubsystem is continuously updated.

A method 700 for distributed control through a global processor is shownin FIG. 7. For example, beginning at block 710 the global processorreceives a transmission of subsystem performance objectives from each ofsubsystems 1, 2, and 3. At block 720, the global processor uses thesubsystem performance objectives, as well as other data, to identify aglobal system state. At block 730, the global processor uses the globalsystem state to determine a global performance objective. At block 740,the global processor generates an updated subsystem performanceobjective for each of subsystems 1, 2, and 3. The updated performanceobjective can be oriented to maximize an overall drilling systemparameter while allowing the subsystems to avoid detrimental competitionof shared resources. At block 750, the updated subsystem performanceobjective for each subsystem is transmitted to the correspondingsubsystem. At block 760, the actuator of subsystem 1 is activated suchthat it changes a subsystem parameter to allow the subsystem to meet thenew performance objective. Similarly, the actuators of subsystems 2 and3 are activated at blocks 762 and 764, respectively, to allow subsystems2 and 3 meet the new performance objectives. The above described processcan repeat on a continuous loop, such that the global processor isconstantly updated with the real-time data from each of the subsystems.

EXAMPLES

The following examples are provided to illustrate the subject matter ofthe present application. The examples are not intended to limit thescope of the present disclosure and they should not be so interpreted.The data presented in the following examples was synthesized for thepurpose of demonstration.

Example 1—Modeling and Decomposition

In determining a networked control strategy, a complex model can firstbe identified for the system as a whole and then decomposed into a groupof interaction models for each subsystem. In the alternative a group ofinteraction models for each subsystem can be identified directly fromthe data. An identified complex model for the overall drilling dynamicscan be defined by Equation 1.

{dot over (X)}=F(X,U)  (1)

Wherein X includes the surface, downhole, and fluid states involved inthe drilling dynamics and U includes the surface, downhole and fluidsystem inputs. Model decomposition can be adopted to decompose thecomplex model into a set of physically meaningful subsystem interactionmodels. An exemplary interaction model for rig subsystem can be definedin Equation 2.

{dot over (x)} _(d) =f _(d)(x _(m) ,u _(d) ,x _(d))  (2)

Wherein x_(d) denotes the drilling dynamics state, for example,rotational and translational position and velocity along the drillingpipe and at the drilling bit; u_(d) denotes the rig surface systeminputs, for example, hook load and surface torque; x_(m) denotes thefluid dynamics states, for example, flow rate through drill bit,pressure inside and outside the drill string, fluid density andviscosity, etc. Due to the presence of x_(m) in Eqn. 2, it is shown thatthe force generated by the fluid impacts the drilling dynamics.

An interaction model for fluid dynamics, such as those involved in themud circulation system, can be defined by Equation 3.

{dot over (x)} _(m) =f _(m)(x _(m) ,u _(m) ,x _(d))  (3)

Wherein u_(m) denotes inputs from the mud circulation system, forexample, pump pressure, flow rate, and choke opening. The force orientedfrom the drill pipe rotational seed and ROP, shown in Eqn. 3 as x_(d),can impact the upstream choke pressure and flow rate through the drillbit.

In this example, the choke opening is controlled in order to regulatethe downhole pressure. These parameters are entered into Eqn. 3 usingEquations 4-7, below.

$\begin{matrix}{{\frac{V_{d}}{\beta_{d}}{\overset{.}{p}}_{p}} = {q_{p} - q_{bit}}} & (4) \\{{M\; {\overset{.}{q}}_{bit}} = {p_{p} - p_{c} - {F\left( {q_{bit},\omega_{d}} \right)} + {\left( {\rho_{d} - \rho_{a}} \right){gh}_{dh}}}} & (5) \\{{\frac{V_{a}}{\beta_{a}}{\overset{.}{p}}_{c}} = {q_{bit} + q_{bpp} - {A_{d}v_{d}} - q_{c} + q_{err}}} & (6) \\{q_{c} = {K_{c}\sqrt{p_{c} - {p_{c\; 0}{G\left( u_{c} \right)}}}}} & (7)\end{matrix}$

Wherein

p_(p) Main pump pressure p_(c) Upstream choke pressure p_(co) Downstreamchoke pressure q_(bit) Flow rate through the drilling bit q_(p) Mainpump flow rate q_(bpp) Back pressure pump flow rate q_(c) Flow ratethrough the choke u_(c) Control input, choke opening q_(err) Modeluncertainty variable, unmodelled flow rate in the annulus includingpossible drilling mud or influx of reservoir fluids ν_(d) Drillingstring velocity relative to the well ω_(d) Rotational velocity of thedrill string

The system described above only takes the effect of the mud subsystemstate, input, and constraints, and drilling subsystem state intoconsideration. In order to include the BHA subsystem, Equation 8 can beused.

{dot over (x)} _(B) =f _(B)(x _(B) ,u _(B) ,x _(d) ,x _(m))  (8)

Wherein u_(B) denotes the inputs of the BHA navigation system, forexample, the toolface and mud motor flow rate, and x_(B) denotes the BHAposition and attitude states. The presence of x_(d) and x_(m) indicatethat the WOB force and flow rate at drill bit impact the BHA directionand position.

During drilling operations, a short term linear model can be used toapproximate the dynamics, as shown in Eqns. 2-8, in order to takevarious elements into account. For example, change relative to subsystemdynamics, or wear on bit. As such, Eqns. 2-8 can be rewritten for eachsubsystem as shown below in Equation 9.

{dot over (X)} _(ij) =A _(ij) X _(ij) +B _(ij) U _(j)  (9)

Wherein X_(ij) denotes interaction states that reflect the impact ofinput from subsystem j (U_(j)) onto the original states of subsystem i.For example, Eqn. 9 can be used to evaluate the interaction dynamicsbetween the mud circulation system and the drilling system, whereinX_(ij) denotes the interaction states (such as drill string, bittranslation, rotational position, and rotational speed) which reflectthe input from the mud circulation system (such as pump pressure, flowrate, and choke opening).

The model described above can be initialized based on the offset data orfrom the first principles, and can be modified adaptively to capture thedrilling dynamics. For example, with the same real-time surface inputs,the residues between the visual outputs from the current model and thereal bit outputs are larger than a predefined threshold, the systemidentification can be triggered and the drilling model updated.

In the alternative, if an eigenvalue drift is adopted as the performancemetric, the modeling and decomposition module will learn the eigenvaluechanges for the current model structure from the current data. If thechanges exceed a predefined limit, the model structure can bere-identified. Furthermore, a set of linear approximations can beevaluated by the eigenvalue drifts from both current and past data andwhichever is more robust to changes and disturbances can be selected. Asthe drilling operation conditions (such as the bit wear, motor wear, androck mechanics) change slowly, the model parameters are updated lessfrequently to maintain a pre-specified accuracy.

Example 2—Distributed Control

Once an interaction model has been determined for each subsystem, thedata can be transmitted to a corresponding computation processor forlocal optimal controller design. For the purposes of this Example, anMPC controller is used. The controller design can be configured toaccept local constraints and real-time physical inputs from each of theplurality of subsystems. At each step, the subsystem controllers searchfor the subsystem's best control command in order to advance the overallobjective function. The system can be set up to achieve a variety ofdifferent overall system objectives, for example cost minimization,equipment wear reduction, or a combination of several differentobjectives.

For the purposes of this Example, the overall system objective is set ascost minimization. The cost minimization objective can be defined asshown in Equation 10.

c(u)=∫a ₁(ROP−ROP*)² +a ₂ r _(d) ² +a ₃ w ² +a ₄(E _(c) −E _(c)*)² +a ₅u ²  (10)

Wherein u denotes the inputs of each of the plurality of subsystems,r_(d) denotes the energy dissipation ratio, w denotes the drill bit andmud motor wear, E_(c) and E_(c)* denote the real and desired cuttingefficiency, respectively, ROP and ROP* denote the real and desired rateof penetration, respectively, and a₁ to a₅ denote the weights that sumto 1, wherein a_(i)≥0 for any i. The weights, a_(i), can be selectedbased on the current drilling requirement. For example, when thereplacement of the drill bit and mud motor are expensive, the weight ondrill bit and motor wear is of considerable value to extend the life orretain the efficiency of drill bit or mud motor.

In the alternative, when only the energy dissipation ratio is evaluated,a₂ is set to be 1 while the other weights are set to be zero, in orderto narrow the cost minimization function to minimize the energydissipation ratio. The energy dissipation ratio is the ratio between thesurface energy and the effective drill bit working energy. Surfaceenergy can be calculated from the surface hook load and pump rate, andeffective drill bit working energy is calculated from ROP and theplanned well path.

In real-time, the cooperative and distributed controllers would achievethe overall objective as follows. Assuming, for the purposes for thisExample, a cost function as described by Eqn. 10, at each time step,each of the plurality of subsystems searches for its entire local inputregion Ω_(i) to minimize cost via the MPC method. The most beneficialcontrol input for the ith subsystem can be expressed as shown inEquation 11.

U _(i)*=arg min_(U) _(i) _(ϵΩ) _(i) c,under local constraints  (11)

The controller design for each subsystem can be performed in parallel,however each subsystem can be performed at a different rate, allowingfor distributed control. Each calculated local optimal input, forexample, rig inputs, pump and choke inputs, and BHA inputs, can betransmitted to a global processing module for further calculation.

Example 3—Global Optimization

A global processing module can collect local optimal inputs U_(i)* fromeach subsystem. Once the data is complied, a simple iteration ofweighted summation of functions of all the U_(i)* is performed toguarantee the convergence of U*=[U₁*, U₂*, . . . , U_(N)*] to theoptimal global input U**=[U₁**, U₂**, . . . , U_(N)**]. Thecorresponding component of U** (for example, rig inputs, pump and chokeinputs, and BHA inputs) can be applied to each of the subsystems vialocal controllers. Such controllers can be, for example, aproportional-integral-derivative (PID) controller.

Example 4—Smart Communication

A smart model communication scheme can be used to determine the timerequired to updated models for each subsystem by evaluating the system'sperformance. The closed loop performance of each subsystem can beevaluated in real-time and performance index of each subsystem can beone of eigenvalue drift or control performance.

FIG. 8A shows an example of when a subsystem's control performancedegrades from (1) to (2). As shown, interaction model for the system nolonger matches the actual system output, thus an immediate communicationcan be adopted in order to update the interaction model. This type ofdegradation can also indicate that the closed loop eigenvalues havedrifted closer to the imaginary axis, as shown in FIG. 8B.

In the alternative, the distributed system's performance may besensitive to communication time delay. In order to reduce the impact ofthe delay to the system's performance a smart input/communication schemecan be included. An example of the impact of one subsystem's inputs onthe overall system performance is shown in FIG. 9A. The volume withinthe cylinder of FIG. 9A denotes the undesired system operation region,for example, the surface operation region that could induce stick-slip(an action characterized by the absorption and release of energy as afunction of the difference between static and dynamic friction). Theundesired region can vary as a function of the communication time delay.FIG. 9B shows a contour figure corresponding to FIG. 9A. For thepurposes of FIG. 9B, assume the rig subsystem is at current operationpoint A and the next calculated operation point is B, the transitionpath cannot be a straight path (x) as shown in FIG. 9B, because it wouldtravel through the undesired region (as shown in FIG. 9A) and introduceproblems to the system, for example, stick-slip.

When no communication delay is present, the shortest transition path (0)can be adopted as the communication/input operation profile, tocircumvent the undesired region. As the communication delay increases,the undesired region expands correspondingly. Therefore, when thecommunication delay time increases, the communication/input operationprofile is adaptively adjusted. For example, in the presence ofcommunication delay time 1, the shortest path (1) is adopted as theprofile to circumvent the undesired region 1. Similarly, whencommunication delay time 2 occurs, the shortest path (2) is adopted asthe profile to circumvent the undesired region 2.

In the alternative to the operation region-communication delayrelationship, the eigenvalue drift-communication delay relationship canbe adopted in order to determine the communication/input operationprofile. The profile can be designed under the allowed eigenvalue drift,as shown in FIG. 10, wherein the profile (1) of WOB* is adapted toprofile (2) to satisfy the eigenvalue drift constraints associated withthe current communication delay.

When the subsystems are weakly coupled, real-time communication is notnecessary until the subsystem's structure is changed into a closelycoupled fashion. In the alternative, if the subsystems are closelycoupled the communication bandwidth does not allow real-timecommunication among them; however each subsystem controller is designedwith robust techniques such that the controlled system can tolerate thecommunication delay.

Numerous examples are provided herein to enhance understanding of thepresent disclosure. A specific set of statements are provided asfollows.

Statement 1: A system comprising a plurality of subsystems comprising asubsystem controller communicatively coupled with a sensor, an actuator,and a subsystem processor, wherein the sensor obtains a measurement, andwherein the subsystem processor further comprises a first memory storinginstructions which cause the subsystem processor to identify a subsystemstate, and generate a subsystem performance objective based at least inpart on the subsystem state; and a global processor communicativelycoupled with each of the plurality of subsystems, the global processorcomprising a second memory storing instructions which cause the globalprocessor to identify a global system state based at least in part onthe subsystem state of each of the plurality of subsystems, generate aglobal performance objective based at least in part on the global systemstate, calculate an updated subsystem performance objective for each ofthe plurality of subsystems, and transmit the updated subsystemperformance objective to each of the plurality of subsystems; andwherein the subsystem controller in each of the plurality of subsystemsactivates the actuator to adjust a subsystem parameter to meet theupdated subsystem performance objective.

Statement 2: A system according to Statement 1, wherein each of theplurality of subsystems are one of a rig subsystem, a drilling fluidsubsystem, and a bottom hole assembly (BHA) subsystem.

Statement 3: A system according to Statement 1 or Statement 2, whereinthe measurement taken by the sensor of the BHA subsystem is selectedfrom the group consisting of a formation resistivity near the drill bit,a formation gamma ray intensity, a formation porosity, a formationlithology, an inclination of the drill string, an azimuth of the drillstring, a downhole fluid pressure, a shock, a vibration, a torque, arevolution per minute (RPM) of the fluid-driven motor, a change intorque of the fluid-driven motor, a change in power of the fluid-drivenmotor, a drill string telemetry, and a drill bit telemetry.

Statement 4: A system according to Statements 1-3, wherein the sensor ofthe BHA subsystem is selected from the group consisting of an acousticlogging tool, a neutron logging tool, a gamma ray logging tool, adensity logging tool, a photoelectron logging tool, and a nuclearmagnetic resonance (NMR) logging tool.

Statement 5: A system according to Statements 1-4, wherein the subsystemparameter controlled by the actuator of the BHA subsystem is selectedfrom the group consisting of a well path, a drill bit orientation, apath, a steering, and a drill string orientation.

Statement 6: A system according to Statements 1-5, wherein the subsystemcontroller of the BHA subsystem transmits measurements obtained from thesensor to the global processor.

Statement 7: A system according to Statements 1-6, wherein themeasurement taken by the sensor of the drilling fluid subsystem isselected from the group consisting of a drilling fluid flow rate, adrilling fluid pump rate, a volume of cuttings, a lithology of cuttings,a quantity of cuttings, a weight of cuttings, a density of cuttings, ashape and morphology of cuttings, a visual characteristics of cuttings,a particle size distribution (PSD) of cuttings, a weight and volume offines, a PSD of fines, a drilling fluid rheology, a drilling fluiddensity, an electrical stability of the drilling fluid, a percentsolids, an oil to water ratio, a drilling fluid pH, a drilling fluidsalinity, and a PSD of the drilling fluid.

Statement 8: A system according to Statements 1-7, wherein the subsystemparameter controlled by the actuator of the drilling fluid subsystem isselected from the group consisting of a drilling fluid pumping rate, adrilling fluid flow rate, a shaker screen desk angle, a shakervibration, a shake G-force, a cutting conveyance velocity, a drillingfluid composition, a drilling fluid additive supply valve, a drillingfluid additive feed rate, and a drilling fluid discharge rate.

Statement 9: A system according to Statements 1-8, wherein themeasurement taken by the sensor of the rig subsystem is selected fromthe group consisting of a revolution per minute (RPM), a weight-on-bit(WOB), a torque-on-bit (TOB), a rate of penetration (ROP), a well depth,a hook load, and a standpipe pressure.

Statement 10: A system according to Statements 1-9, wherein thesubsystem parameter controlled by the actuator of the rig subsystem isselected from the group consisting of an RPM, a WOB, a TOB, an ROP, anda hook load.

Statement 11: A system according to Statements 1-10, wherein thesubsystem controller transmits a plurality of control signals to theactuator.

Statement 12: A system according to Statements 1-11, wherein the globalperformance objective is one of a cost minimization, an equipment lifeextension, and a combination thereof.

Statement 13: A method comprising providing a drilling system comprisinga plurality of subsystems, each of the plurality of subsystemscomprising a subsystem controller communicatively coupled with a sensor,an actuator, and a subsystem processor; obtaining, at the sensor, ameasurement; identifying, at each of the subsystem processors, asubsystem state; generating, at each of the subsystem processors, asubsystem performance objective; providing a global processorcommunicatively coupled with each of the plurality of subsystems;transmitting, from each of the subsystem controllers, the subsystemstate and the subsystem performance objective to the global processor;identifying, at the global processor, a global system state based atleast in part on the subsystem state of each of the plurality ofsubsystems; determining, at the global processor, a global performanceobjective; generating, at the global processor, an updated subsystemperformance objective for each of the plurality of subsystems;transmitting, from the global processor, the updated subsystemperformance objective to each of the plurality of subsystems; andactivating, at each of the plurality of subsystems, the actuator toadjust a subsystem parameter to meet the updated subsystem performanceobjective.

Statement 14: A method according to Statement 13, wherein each of theplurality of subsystems are one of a rig subsystem, a drilling fluidsubsystem, and a bottom hole assembly (BHA) subsystem.

Statement 15: A method according to Statement 13 or Statement 14,wherein the measurement taken by the sensor of the BHA subsystem isselected from the group consisting of a formation resistivity near thedrill bit, a formation gamma ray intensity, a formation porosity, aformation lithology, an inclination of the drill string, an azimuth ofthe drill string, a downhole fluid pressure, a shock, a vibration, atorque, a revolution per minute (RPM) of the fluid-driven motor, achange in torque of the fluid-driven motor, a change in power of thefluid-driven motor, a drill string telemetry, and a drill bit telemetry.

Statement 16: A method according to Statements 13-15, wherein the sensorof the BHA subsystem is selected from the group consisting of anacoustic logging tool, a neutron logging tool, a gamma ray logging tool,a density logging tool, a photoelectron logging tool, and a nuclearmagnetic resonance (NMR) logging tool.

Statement 17: A method according to Statements 13-16, wherein thesubsystem parameter controlled by the actuator of the BHA subsystem isselected from the group consisting of a well path, a drill bitorientation, a path, a steering, and a drill string orientation.

Statement 18: A method according to Statements 13-17, wherein thesubsystem controller of the BHA subsystem transmits measurementsobtained from the sensor to the global processor.

Statement 19: A method according to Statements 13-18, wherein themeasurement taken by the sensor of the drilling fluid subsystem isselected from the group consisting of a drilling fluid flow rate, adrilling fluid pump rate, a volume of cuttings, a lithology of cuttings,a quantity of cuttings, a weight of cuttings, a density of cuttings, ashape and morphology of cuttings, a visual characteristics of cuttings,a particle size distribution (PSD) of cuttings, a weight and volume offines, a PSD of fines, a drilling fluid rheology, a drilling fluiddensity, an electrical stability of the drilling fluid, a percentsolids, an oil to water ratio, a drilling fluid pH, a drilling fluidsalinity, and a PSD of the drilling fluid.

Statement 20: A method according to Statements 13-19, wherein thesubsystem parameter controlled by the actuator of the drilling fluidsubsystem is selected from the group consisting of a drilling fluidpumping rate, a drilling fluid flow rate, a shaker screen desk angle, ashaker vibration, a shake G-force, a cutting conveyance velocity, adrilling fluid composition, a drilling fluid additive supply valve, adrilling fluid additive feed rate, and a drilling fluid discharge rate.

Statement 21: A method according to Statements 13-20, wherein themeasurement taken by the sensor of the rig subsystem is selected fromthe group consisting of a revolution per minute (RPM), a weight-on-bit(WOB), a torque-on-bit (TOB), a rate of penetration (ROP), a well depth,a hook load, and a standpipe pressure.

Statement 22: A method according to Statements 13-21, wherein thesubsystem parameter controlled by the actuator of the rig subsystem isselected from the group consisting of an RPM, a WOB, a TOB, an ROP, anda hook load.

Statement 23: A method according to Statements 13-22, further comprisingtransmitting a plurality of control signals from the subsystemcontroller to the actuator.

Statement 24: A method according to Statements 13-23, wherein the globalperformance objective is one of a cost minimization, an equipment lifeextension, and a combination thereof.

Statement 25: A method according to Statements 13-24, further comprisingrepeating the method to provide a continuously updated performanceobjective to each of the plurality of subsystems.

Statement 26: A method comprising providing a drilling system comprisinga plurality of subsystems, each of the plurality of subsystemscomprising a subsystem controller communicatively coupled with a sensor,an actuator, and a subsystem processor; providing a global processorcommunicatively coupled with each of the plurality of subsystems;determining, at the global processor, a global performance objective;obtaining, at the each of the plurality of sensors, a measurement;transmitting, from each of the subsystem controllers, the subsystemstate and the subsystem performance objective to the global processor;generating, at the global processor, a controller design; transmitting,from the global processor, the controller design to the subsystemcontroller for each of the plurality of subsystems; and activating, ateach of the plurality of subsystems, the actuator to adjust a subsystemparameter to meet the controller design.

Statement 27: A method according to Statement 26, wherein each of theplurality of subsystems are one of a rig subsystem, a drilling fluidsubsystem, and a bottom hole assembly (BHA) subsystem.

Statement 28: A method according to Statement 26 or Statement 27,wherein the measurement taken by the sensor of the BHA subsystem isselected from the group consisting of a formation resistivity near thedrill bit, a formation gamma ray intensity, a formation porosity, aformation lithology, an inclination of the drill string, an azimuth ofthe drill string, a downhole fluid pressure, a shock, a vibration, atorque, a revolution per minute (RPM) of the fluid-driven motor, achange in torque of the fluid-driven motor, a change in power of thefluid-driven motor, a drill string telemetry, and a drill bit telemetry.

Statement 29: A method according to Statements 26-28, wherein the sensorof the BHA subsystem is selected from the group consisting of anacoustic logging tool, a neutron logging tool, a gamma ray logging tool,a density logging tool, a photoelectron logging tool, and a nuclearmagnetic resonance (NMR) logging tool.

Statement 30: A method according to Statements 26-29, wherein thesubsystem parameter controlled by the actuator of the BHA subsystem isselected from the group consisting of a well path, a drill bitorientation, a path, a steering, and a drill string orientation.

Statement 31: A method according to Statements 26-30, wherein thesubsystem controller of the BHA subsystem transmits measurementsobtained from the sensor to the global processor.

Statement 32: A method according to Statements 26-31, wherein themeasurement taken by the sensor of the drilling fluid subsystem isselected from the group consisting of a drilling fluid flow rate, adrilling fluid pump rate, a volume of cuttings, a lithology of cuttings,a quantity of cuttings, a weight of cuttings, a density of cuttings, ashape and morphology of cuttings, a visual characteristics of cuttings,a particle size distribution (PSD) of cuttings, a weight and volume offines, a PSD of fines, a drilling fluid rheology, a drilling fluiddensity, an electrical stability of the drilling fluid, a percentsolids, an oil to water ratio, a drilling fluid pH, a drilling fluidsalinity, and a PSD of the drilling fluid.

Statement 33: A method according to Statements 26-32, wherein thesubsystem parameter controlled by the actuator of the drilling fluidsubsystem is selected from the group consisting of a drilling fluidpumping rate, a drilling fluid flow rate, a shaker screen desk angle, ashaker vibration, a shake G-force, a cutting conveyance velocity, adrilling fluid composition, a drilling fluid additive supply valve, adrilling fluid additive feed rate, and a drilling fluid discharge rate.

Statement 34: A method according to Statements 26-33, wherein themeasurement taken by the sensor of the rig subsystem is selected fromthe group consisting of a revolution per minute (RPM), a weight-on-bit(WOB), a torque-on-bit (TOB), a rate of penetration (ROP), a well depth,a hook load, and a standpipe pressure.

Statement 35: A method according to Statements 26-34, wherein thesubsystem parameter controlled by the actuator of the rig subsystem isselected from the group consisting of an RPM, a WOB, a TOB, an ROP, anda hook load.

Statement 36: A method according to Statements 26-35, further comprisingtransmitting a plurality of control signals from the subsystemcontroller to the actuator.

Statement 37: A method according to Statements 26-36, wherein thecontroller design maximizes one of a cost minimization, an equipmentlife extension, and a combination thereof.

Statement 38: A method according to Statements 26-37, further comprisingrepeating the method to provide a continuously updated controller designto each of the plurality of subsystems.

Statement 39: A method according to Statements 26-38, wherein thecontroller design accounts for a plurality of local constraints uniqueto each of the plurality of subsystems.

Statement 40: An apparatus comprising a plurality of subsystemscommunicatively coupled with a global processor, wherein each of theplurality of subsystems comprises a controller communicatively coupledwith a sensor, an actuator, and a processor, and wherein the processorfurther comprises a memory storing instructions which cause theprocessor to receive, from the sensor, a measurement, identify asubsystem state, generate, at the processor, a subsystem performanceobjective, transmit, from the controller, the subsystem state and thesubsystem performance objective to the global processor, receive, fromthe global processor, an updated subsystem performance objective, andactivate the actuator to adjust a parameter to meet the updatedperformance objective.

Statement 41: An apparatus according to Statement 40, wherein each ofthe plurality of subsystems are one of a rig subsystem, a drilling fluidsubsystem, and a bottom hole assembly (BHA) subsystem.

Statement 42: An apparatus according to Statement 40 or Statement 41,wherein the measurement taken by the sensor of the BHA subsystem isselected from the group consisting of a formation resistivity near thedrill bit, a formation gamma ray intensity, a formation porosity, aformation lithology, an inclination of the drill string, an azimuth ofthe drill string, a downhole fluid pressure, a shock, a vibration, atorque, a revolution per minute (RPM) of the fluid-driven motor, achange in torque of the fluid-driven motor, a change in power of thefluid-driven motor, a drill string telemetry, and a drill bit telemetry.

Statement 43: An apparatus according to Statement 40-42, wherein thesensor of the BHA subsystem is selected from the group consisting of anacoustic logging tool, a neutron logging tool, a gamma ray logging tool,a density logging tool, a photoelectron logging tool, and a nuclearmagnetic resonance (NMR) logging tool.

Statement 44: An apparatus according to Statements 40-43, wherein theparameter controlled by the actuator of the BHA subsystem is selectedfrom the group consisting of a well path, a drill bit orientation, apath, a steering, and a drill string orientation.

Statement 45: An apparatus according to Statements 40-44, wherein thecontroller of the BHA subsystem transmits measurements obtained from thesensor to the global processor.

Statement 46: An apparatus according to Statements 40-45, wherein themeasurement taken by the sensor of the drilling fluid subsystem isselected from the group consisting of a drilling fluid flow rate, adrilling fluid pump rate, a volume of cuttings, a lithology of cuttings,a quantity of cuttings, a weight of cuttings, a density of cuttings, ashape and morphology of cuttings, a visual characteristics of cuttings,a particle size distribution (PSD) of cuttings, a weight and volume offines, a PSD of fines, a drilling fluid rheology, a drilling fluiddensity, an electrical stability of the drilling fluid, a percentsolids, an oil to water ratio, a drilling fluid pH, a drilling fluidsalinity, and a PSD of the drilling fluid.

Statement 47: An apparatus according to Statements 40-46, wherein theparameter controlled by the actuator of the drilling fluid subsystem isselected from the group consisting of a drilling fluid pumping rate, adrilling fluid flow rate, a shaker screen desk angle, a shakervibration, a shake G-force, a cutting conveyance velocity, a drillingfluid composition, a drilling fluid additive supply valve, a drillingfluid additive feed rate, and a drilling fluid discharge rate.

Statement 48: An apparatus according to Statements 40-47, wherein themeasurement taken by the sensor of the rig subsystem is selected fromthe group consisting of a revolution per minute (RPM), a weight-on-bit(WOB), a torque-on-bit (TOB), a rate of penetration (ROP), a well depth,a hook load, and a standpipe pressure.

Statement 49: An apparatus according to Statements 40-48, wherein theparameter controlled by the actuator of the rig subsystem is selectedfrom the group consisting of an RPM, a WOB, a TOB, an ROP, and a hookload.

Statement 50: An apparatus according to Statements 40-49, wherein thecontroller transmits a plurality of control signals to the actuator.

Statement 51: An apparatus according to Statements 40-50, wherein theglobal performance objective is one of a cost minimization, an equipmentlife extension, and a combination thereof.

Statement 52: An apparatus comprising a global processor communicativelycoupled with a plurality of subsystems, wherein the global processorfurther comprises a memory storing instructions which cause the globalprocessor to receive a subsystem state and a subsystem performanceobjective from each of the plurality of subsystems, identify a globalsystem state based at least in part on the subsystem state of each ofthe plurality of subsystems, generate a global performance objective,calculate an updated subsystem performance objective for each of theplurality of subsystems, and transmit the updated subsystem performanceobjective to each of the plurality of subsystems.

Statement 53: An apparatus according to Statement 52, wherein each ofthe plurality of subsystems are one of a rig subsystem, a drilling fluidsubsystem, and a bottom hole assembly (BHA) subsystem.

Statement 54: An apparatus according to Statement 52 or Statement 53,wherein the global performance objective is one of a cost minimization,an equipment life extension, and a combination thereof.

The embodiments shown and described above are only examples. Even thoughnumerous characteristics and advantages of the present technology havebeen set forth in the foregoing description, together with details ofthe structure and function of the present disclosure, the disclosure isillustrative only, and changes may be made in the detail, especially inmatters of shape, size and arrangement of the parts within theprinciples of the present disclosure to the full extent indicated by thebroad general meaning of the terms used in the attached claims. It willtherefore be appreciated that the embodiments described above may bemodified within the scope of the appended claims.

What is claimed is:
 1. A system comprising: a plurality of subsystemscomprising: a subsystem controller communicatively coupled with asensor, an actuator, and a subsystem processor, wherein the sensorobtains a measurement, and wherein the subsystem processor furthercomprises a first memory storing instructions which cause the subsystemprocessor to: identify a subsystem state, and generate a subsystemperformance objective based at least in part on the subsystem state; anda global processor communicatively coupled with each of the plurality ofsubsystems, the global processor comprising a second memory storinginstructions which cause the global processor to: identify a globalsystem state based at least in part on the subsystem state of each ofthe plurality of subsystems, generate a global performance objectivebased at least in part on the global system state, calculate an updatedsubsystem performance objective for each of the plurality of subsystems,and transmit the updated subsystem performance objective to each of theplurality of subsystems; and wherein the subsystem controller in each ofthe plurality of subsystems activates the actuator to adjust a subsystemparameter to meet the updated subsystem performance objective.
 2. Thesystem of claim 1, wherein each of the plurality of subsystems are oneof a rig subsystem, a drilling fluid subsystem, and a bottom holeassembly (BHA) subsystem.
 3. The system of claim 2, wherein thesubsystem parameter controlled by the actuator of the BHA subsystem isselected from the group consisting of a well path, a drill bitorientation, a path, a steering, and a drill string orientation.
 4. Thesystem of claim 2, wherein the subsystem parameter controlled by theactuator of the drilling fluid subsystem is selected from the groupconsisting of a drilling fluid pumping rate, a drilling fluid flow rate,a shaker screen desk angle, a shaker vibration, a shake G-force, acutting conveyance velocity, a drilling fluid composition, a drillingfluid additive supply valve, a drilling fluid additive feed rate, and adrilling fluid discharge rate.
 5. The system of claim 2, wherein thesubsystem parameter controlled by the actuator of the rig subsystem isselected from the group consisting of an RPM, a WOB, a TOB, an ROP, anda hook load.
 6. The system of claim 1, wherein the subsystem controllertransmits a plurality of control signals to the actuator.
 7. The systemof claim 1, wherein the global performance objective is one of a costminimization, an equipment life extension, and a combination thereof. 8.A method comprising: providing a drilling system comprising a pluralityof subsystems, each of the plurality of subsystems comprising asubsystem controller communicatively coupled with a sensor, an actuator,and a subsystem processor; providing a global processor communicativelycoupled with each of the plurality of subsystems; determining, at theglobal processor, a global performance objective; obtaining, at the eachof the plurality of sensors, a measurement; transmitting, from each ofthe subsystem controllers, a subsystem state and a subsystem performanceobjective to the global processor; generating, at the global processor,a controller design; transmitting, from the global processor, thecontroller design to the subsystem controller for each of the pluralityof subsystems; and activating, at each of the plurality of subsystems,the actuator to adjust a subsystem parameter to meet the controllerdesign.
 9. The method of claim 8, wherein each of the plurality ofsubsystems are one of a rig subsystem, a drilling fluid subsystem, and abottom hole assembly (BHA) subsystem.
 10. The method of claim 9, whereinthe subsystem parameter controlled by the actuator of the BHA subsystemis selected from the group consisting of a well path, a drill bitorientation, a path, a steering, and a drill string orientation.
 11. Themethod of claim 9, wherein the subsystem parameter controlled by theactuator of the drilling fluid subsystem is selected from the groupconsisting of a drilling fluid pumping rate, a drilling fluid flow rate,a shaker screen desk angle, a shaker vibration, a shake G-force, acutting conveyance velocity, a drilling fluid composition, a drillingfluid additive supply valve, a drilling fluid additive feed rate, and adrilling fluid discharge rate.
 12. The method of claim 9, wherein thesubsystem parameter controlled by the actuator of the rig subsystem isselected from the group consisting of an RPM, a WOB, a TOB, an ROP, anda hook load.
 13. The method of claim 8, wherein the controller designmaximizes one of a cost minimization, an equipment life extension, and acombination thereof.
 14. The method of claim 8, further comprisingrepeating the method to provide a continuously updated controller designto each of the plurality of subsystems.
 15. An apparatus comprising: aplurality of subsystems communicatively coupled with a global processor,wherein each of the plurality of subsystems comprises a controllercommunicatively coupled with a sensor, an actuator, and a processor, andwherein the processor further comprises a memory storing instructionswhich cause the processor to: receive, from the sensor, a measurement,identify a subsystem state, generate, at the processor, a subsystemperformance objective, transmit, from the controller, the subsystemstate and the subsystem performance objective to the global processor,receive, from the global processor, an updated subsystem performanceobjective, and activate the actuator to adjust a parameter to meet theupdated performance objective.
 16. The apparatus of claim 15, whereineach of the plurality of subsystems are one of a rig subsystem, adrilling fluid subsystem, and a bottom hole assembly (BHA) subsystem.17. The apparatus of claim 16, wherein the parameter controlled by theactuator of the BHA subsystem is selected from the group consisting of awell path, a drill bit orientation, a path, a steering, and a drillstring orientation.
 18. The apparatus of claim 16, wherein the parametercontrolled by the actuator of the drilling fluid subsystem is selectedfrom the group consisting of a drilling fluid pumping rate, a drillingfluid flow rate, a shaker screen desk angle, a shaker vibration, a shakeG-force, a cutting conveyance velocity, a drilling fluid composition, adrilling fluid additive supply valve, a drilling fluid additive feedrate, and a drilling fluid discharge rate.
 19. The apparatus of claim16, wherein the parameter controlled by the actuator of the rigsubsystem is selected from the group consisting of an RPM, a WOB, a TOB,an ROP, and a hook load.
 20. The apparatus of claim 15, wherein a globalperformance objective is one of a cost minimization, an equipment lifeextension, and a combination thereof.